1. Field of the Invention
This invention relates to viscoelastic fluids, in particular, viscoelastic oilfield stimulation fluids containing nanotubes.
2. Description of the Related Art
Various types of oilfield stimulation fluids are used in operations related to the development, completion, and production of natural hydrocarbon reservoirs. These operations include fracturing subterranean formations, modifying the permeability of subterranean formations, or sand control. The oilfield stimulation fluids employed in these operations are known as drilling fluids, completion fluids, work over fluids, packer fluids, fracturing fluids, drilling fluids, conformance or permeability control fluids, and the like.
Viscoelastic fluids are useful for carrying particles from one region of the formation, for instance, the wellbore or surface equipment, to another. As an example, one of the functions of a drilling fluid is to carry drilling cuttings from around the drilling bit out of the wellbore to the surface. Viscoelastic fluids also play an essential role for instance in gravel packing placement. Gravel packing essentially consists of placing a gravel pack around the perimeter of a wellbore across the production zone to minimize sand production from highly permeable formations.
In the recovery of hydrocarbons from subterranean formations it is common practice, particularly in formations of low permeability, to fracture the hydrocarbon-bearing formation to provide flow channels, using viscoelastic fluids. These flow channels facilitate movement of the hydrocarbons to the wellbore so that the hydrocarbons may be produced from the well. Fracturing involves breaking a portion of the surrounding strata, by injecting a fluid directed at the face of the geologic formation, at pressures sufficient to initiate and/or extend a fracture in the formation. A fracturing fluid typically comprises a proppant, such as ceramic beads or sand to hold the fracture open after the pressure is released. It is therefore important for the viscoelastic fluid to have viscosity properties sufficient to suspend and carry the proppant into the fracture zone, and at the environmental conditions present in the zone.
Viscoelastic surfactant fluids are normally made by mixing in appropriate amounts suitable surfactants such as anionic, cationic, nonionic and zwitterionic surfactants. The viscosity of viscoelastic surfactant fluids is attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate due to intermolecular attraction, or non-covalent bonds (i.e. hydrogen bonding and van der waals forces), to form species such as micelles. The micelles can further interact, also by intermolecular attraction, to form a network exhibiting elastic behavior. In the remaining part of this description, the term “micelle” will be used as a generic term for the organized interacting species.
The viscoelasticity of the surfactant solutions forms rapidly on mixing the various components. If the resulting viscosity of the viscoelastic gel is too high, handling or placement can become difficult. Conversely, when viscosity is too low, other difficulties may be presented, for example, the viscoelastic gel may not transport other components or materials effectively. Any application of viscoelastic surfactant solutions related to transport or placement after their preparation would benefit from a method of controlling their viscosities and gel times.
Micellar viscoelastic fluids have limited use for fracturing high permeability formations. In such environments, low concentrations of viscoelastic surfactants in fracturing fluids may not be sufficient to preclude fluid losses into the porous media of the high permeability formations due to low viscosity properties, thus requiring high concentrations of viscoelastic surfactant to maintain sufficient viscosity to limit fluid loss. This is especially the case at higher fracture zone temperatures; for example, up to about 110° C. Hundreds of thousands to millions of gallons of fracturing fluid must typically be pumped down the wellbore to fracture such wells. The result is a significant increase in cost and resource requirements for the operation. Fluid lost to the formation may also problems with the function or technique of the fracture. For example, the undesirable loss of fluid into the formation limits the fracture size and geometry that can be created during the fracturing pressure pumping operation. Thus, the total volume of the fracture, or crack, is limited by the lost fluid volume that is lost into the rock, because such lost fluid is unavailable to apply volume and pressure to the rock face.
Therefore, the need exists for oilfield stimulation fluids with low viscoelastic surfactant concentrations with sufficient viscosity properties that can perform at higher temperatures, resist fluid loss into the formation, and increase hydrocarbon production. A fluid that can achieve the above while improving the precision with which fluids are delivered, and reduce equipment or operational requirements, would be highly desirable, and the need is met at least in part by the following invention.